Hydraulic fracturing is a method of using pump rate and hydraulic pressure to fracture or crack a subterranean formation. Once the crack or cracks are made, high permeability proppant, relative to the formation permeability, is pumped into the fracture to prop open the crack. When the applied pump rates and pressures are reduced or removed from the formation, the crack or fracture cannot close or heal completely because the high permeability proppant keeps the crack open. The propped crack or fracture provides a high permeability path connecting the producing wellbore to a larger formation area to enhance the production of hydrocarbons.
The development of suitable fracturing fluids is a complex art because the fluids must simultaneously meet a number of conditions. For example, they must be stable at high temperatures and/or high pump rates and shear rates that can cause the fluids to degrade and prematurely settle out the proppant before the fracturing operation is complete. Various fluids have been developed, but most commercially used fracturing fluids are aqueous based liquids that have either been gelled or foamed. When the fluids are gelled, typically a polymeric gelling agent, such as a solvatable polysaccharide, is used. The thickened or gelled fluid helps keep the proppants within the fluid. Gelling can be accomplished or improved by the use of crosslinking agents or crosslinkers that promote crosslinking of the polymers together, thereby increasing the viscosity of the fluid.
The recovery of fracturing fluids may be accomplished by reducing the viscosity of the fluid to a low value so that it may flow naturally from the formation under the influence of formation fluids. Crosslinked gels generally require viscosity breakers to be injected to reduce the viscosity or “break” the gel. Enzymes, oxidizers, and acids are known polymer viscosity breakers. Enzymes are effective within a pH range, typically a 2.0 to 10.0 range, with increasing activity as the pH is lowered towards neutral from a pH of 10.0. Most conventional borate crosslinked fracturing fluids and breakers are designed from a fixed high crosslinked fluid pH value at ambient temperature and/or reservoir temperature. Optimizing the pH for a borate crosslinked gel is important to achieve proper crosslink stability and controlled enzyme breaker activity.
While polymers have been used in the past as gelling agents in fracturing fluids to carry or suspend solid particles as noted, such polymers require separate breaker compositions to be injected to reduce the viscosity. Further, such polymers tend to leave a coating on the proppant and a filter cake of dehydrated polymer on the fracture face even after the gelled fluid is broken. The coating and/or the filter cake may interfere with the functioning of the proppant. Studies have also shown that “fish-eyes” and/or “microgels” present in some polymer gelled carrier fluids will plug pore throats, leading to impaired leakoff and causing formation damage.
Recently it has been discovered that aqueous drilling and treating fluids may be gelled or have their viscosity increased by the use of non-polymeric viscoelastic surfactants (VES). These VES materials are advantageous over the use of polymer gelling agents in that they do not damage the formation, leave a filter cake on the formation face, coat the proppant or create microgels or “fish-eyes”. It is still necessary, however, to provide some mechanism that will break the viscosity of VES-gelled fluids.
It is known to use bacteria in biodegradation, bioremediation, or microbe enhanced oil recovery (MEOR) techniques. Bacteria are primarily known to decompose reservoir hydrocarbons to produce more easily producible fluids, or to decompose hydrocarbon-based pollutants to environmentally acceptable states.
It is also known that bacteria will degrade drilling fluids. U.S. Pat. No. 3,612,178 discloses a flow-stimulating liquid solution and methods of used based primarily on the combination of a linear alkyl sulfonate as a detergent and penetrant, serving as a special carrier for a lauric amide emulsifier to draw oil into an emulsion and for a phosphate, as sodium phosphate, to draw water into the emulsion. A preservative is added to inhibit deterioration due to bacteria. Similarly, U.S. Pat. No. 3,800,872 relates to methods for recovery of petroleum from a subterranean formation which include injecting into the formation an aqueous flooding medium which assumes a viscosity in oil-rich portions of the formation that is significantly less than the viscosity assumed in the portions low in oil content, the flooding medium thereby preferentially driving the oil, as opposed to water, from the formation. The flooding medium may include a material such as guar that imparts a high viscosity but is subject to rapid degradation by the bacteria in the formation, and a poisoning agent for the bacteria, such as ortho-cresol, which is preferentially soluble in oil. The use of bacteria to directly digest or degrade polymeric gels used in fracturing is also known. However, it is presently unknown to use bacteria and/or enzymes to break viscosities of fluids gelled using viscoelastic surfactants.
General background information concerning biodegrading surfactants may be found in D. R. Karsa, et al., ed., Biodegradability of Surfactants, Blackie Academic & Professional, 1995.
It would be desirable if a viscosity breaking system could be devised to break the viscosity of fracturing fluids gelled with viscoelastic surfactants.